scholarly journals Investigation of Hydraulic and Natural Fracture Interaction: Numerical Modeling or Artificial Intelligence?

10.5772/56382 ◽  
2013 ◽  
Author(s):  
Reza Keshavarzi ◽  
Reza Jahanbakhshi
Keyword(s):  
Artificial Intelligence ◽  
Numerical Modeling ◽  
Natural Fracture ◽  
Fracture Interaction

Natural-hydraulic fracture interaction: Microseismic observations and geomechanical predictions

2015 ◽  
Vol 3 (3) ◽  
pp. SU17-SU31 ◽  
Author(s):  
Jian Huang ◽  
Reza Safari ◽  
Uno Mutlu ◽  
Kevin Burns ◽  
Ingo Geldmacher ◽  
...  
Keyword(s):  
Sensitivity Analysis ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
Natural Fracture ◽  
Design Parameters ◽  
Reservoir Area ◽  
Complex Fracture ◽  
Model Complex ◽  
Fracture Interaction ◽  
The Impact

Natural fractures can reactivate during hydraulic stimulation and interact with hydraulic fractures producing a complex and highly productive natural-hydraulic fracture network. This phenomenon and the quality of the resulting conductive reservoir area are primarily functions of the natural fracture network characteristics (e.g., spacing, height, length, number of fracture sets, orientation, and frictional properties); in situ stress state (e.g., stress anisotropy and magnitude); stimulation design parameters (e.g., pumping schedule, the type/volume of fluid[s], and proppant); well architecture (number and spacing of stages, perforation length, well orientation); and the physics of the natural-hydraulic fracture interaction (e.g., crossover, arrest, reactivation). Geomechanical models can quantify the impact of key parameters that control the extent and complexity of the conductive reservoir area, with implications to stimulation design and well optimization in the field. We have developed a series of geomechanical simulations to predict natural-hydraulic fracture interaction and the resulting fracture network in complex settings. A geomechanics-based sensitivity analysis was performed that integrated key reservoir-geomechanical parameters to forward model complex fracture network generation, synthetic microseismic (MS) response, and associated conductivity paths as they evolve during stimulation operations. The simulations tested two different natural-hydraulic fracture interaction scenarios and could generate synthetic MS events. The sensitivity analysis revealed that geomechanical models that involve complex fracture networks can be calibrated against MS data and can help to predict the reservoir response to stimulation and optimize the conductive reservoir area. We analyzed a field data set (obtained from two hydraulically fractured wells in the Barnett Formation, Tarrant County, Texas) and established a coupling between the geomechanics and MS within the framework of a 3D geologic model. This coupling provides a mechanics-based approach to (1) verify MS trends and anomalies in the field, (2) optimize conductive reservoir area for reservoir simulations, and (3) improve stimulation design on the current well in near-real-time and well design/stimulation for future wells.

Numerical modeling of seismicity induced by fluid injection in naturally fractured reservoirs

Geophysics ◽  
2011 ◽  
Vol 76 (6) ◽  
pp. WC167-WC180 ◽  
Author(s):  
Xueping Zhao ◽  
R. Paul Young
Keyword(s):  
Numerical Modeling ◽  
Fractured Reservoirs ◽  
Seismic Source ◽  
Microseismic Monitoring ◽  
Naturally Fractured Reservoirs ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Field Observations ◽  
Natural Fractures ◽  
Naturally Fractured

The interaction between hydraulic and natural fractures is of great interest for the energy resource industry because natural fractures can significantly influence the overall geometry and effectiveness of hydraulic fractures. Microseismic monitoring provides a unique tool to monitor the evolution of fracturing around the treated rock reservoir, and seismic source mechanisms can yield information about the nature of deformation. We performed a numerical modeling study using a 2D distinct-element particle flow code ([Formula: see text]) to simulate realistic conditions and increase understanding of fracturing mechanisms in naturally fractured reservoirs, through comparisons with results of the geometry of hydraulic fractures and seismic source information (locations, magnitudes, and mechanisms) from both laboratory experiments and field observations. A suite of numerical models with fully dynamic and hydromechanical coupling was used to examine the interaction between natural and induced fractures, the effect of orientation of a preexisting fracture, the influence of differential stress, and the relationship between the fluid front, fracture tip, and induced seismicity. The numerical results qualitatively agree with the laboratory and field observations, and suggest possible mechanics for new fracture development and their interaction with a natural fracture (e.g., a tectonic fault). Therefore, the tested model could help in investigating the potential extent of induced fracturing in naturally fractured reservoirs, and in interpreting microseismic monitoring results to assess the effectiveness of a hydraulic fracturing project.

NUMERICAL SIMULATION OF HYDRAULIC AND NATURAL FRACTURE INTERACTION AND PROPAGATION

2017 ◽  
Author(s):  
Julio Alberto Rueda Cordero ◽  
Cristian Mejia Sanchez. ◽  
Deane Roehl
Keyword(s):  
Numerical Simulation ◽  
Natural Fracture ◽  
Fracture Interaction

scholarly journals On one method of numerical modeling of piezoconductive processes of a two-phase fluid system in a fractured-porous reservoir

2021 ◽  
Vol 2131 (2) ◽  
pp. 022001
Author(s):  
Yu O Bobreneva ◽  
P I Rahimly ◽  
Yu A Poveshchenko ◽  
V O Podryga ◽  
L V Enikeeva
Keyword(s):  
Numerical Modeling ◽  
Nonlinear Approximation ◽  
Natural Fracture ◽  
Physical Processes ◽  
Two Phase ◽  
Fluid Redistribution ◽  
Dual Porosity Model ◽  
Porous Reservoir ◽  
Fluid Transfer ◽  
Phase Fluid

Abstract A method of numerical modeling based on splitting by physical processes of two-phase fluid transfer in a formation with fractured-porous reservoirs is described. Reservoirs of this type have a natural fracture system and are described by the dual porosity model. A four-block mathematical model of the fluid redistribution between a pore-type matrix and a natural fracturing pattern is proposed and studied. The resulting system is complex and entails a number of difficulties associated with a large number of variables and the absence of important properties of a linearized system of equations, such as self-adjointness and symmetry, which are present in the description of piezoconductive processes. The complete splitting by physical processes is carried out to solve this problem. The resulting split model is differentially equivalent to the discrete initial balance equations of the system (conservation of the mass components of the fluids and the total energy of the system), written in divergent form. This approach is associated with a nonlinear approximation of the grid functions in time, which depends on the fraction of the volume occupied by the fluids in the pores, and is easy to implement.

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